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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)

x      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

OR

o         TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to            

Commission File Number 001-32960

GeoMet, Inc.

(Exact name of registrant as specified in its charter)

909 Fannin, Suite 1850

Houston, Texas 77010

(713) 659-3855

(Address of principal executive offices and telephone number, including area code)

N/A

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  x Yes  o No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  x Yes  o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  o Yes  x No

As of May 1, 2012, 40,071,320 shares and 4,838,181 shares, respectively, of the registrant’s common stock and preferred stock, par value $0.001 per share, were outstanding.

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EXPLANATORY NOTE

On May 15, 2012, GeoMet, Inc. (the “Company”) filed its Quarterly Report on Form 10-Q for the quarter ended March 31, 2012 with the Securities and Exchange Commission. The Company is amending such Quarterly Report on Form 10-Q for such quarter to correct three typographical errors as follows:

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Part I. FINANCIAL INFORMATION

Item  1.                                  Financial Statements

GEOMET, INC. AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited)

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GEOMET, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

See accompanying Notes to Consolidated Financial Statements (Unaudited).

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GEOMET, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements

(Unaudited)

Note 1—Organization and Our Business

GeoMet, Inc. (“GeoMet,” “Company,” “we,” or “our”) (formerly GeoMet Resources, Inc.) was incorporated under the laws of the state of Delaware on November 9, 2000. We are an independent natural gas producer primarily involved in the exploration, development and production of natural gas from coal seams (coalbed methane) and non-conventional shallow gas. Our principal operations and producing properties are located in Alabama, West Virginia and Virginia.

The accompanying unaudited consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. All significant intercompany transactions and balances have been eliminated in consolidation. The unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the financial position as of, and results of operations for, the interim periods presented. These unaudited consolidated financial statements have been prepared in accordance with the guidelines of interim reporting; therefore, they do not include all disclosures required for our year-end audited consolidated financial statements prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). Interim period results are not necessarily indicative of results of operations or cash flows for the full year. These unaudited consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements for the fiscal year ended December 31, 2011 and the accompanying notes included in our Annual Report on Form 10-K, which we filed with the Securities and Exchange Commission (the “SEC”) on March 30, 2012.

Note 2—Liquidity and Going Concern Considerations

As of May 11, 2012, we had $148.6 million outstanding under our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”).  As of March 31, 2012, we were in compliance with all of the covenants in our Credit Agreement.  The Credit Agreement provides, however, that if the amount outstanding at any time exceeds the “borrowing base”, we must provide additional collateral to the lenders or repay the excess as provided in the Credit Agreement.  The borrowing base is set in the sole discretion of our lenders in June and December of each year based, in part, on the value of our estimated reserves as determined by the lenders using natural gas prices forecasted by the lenders.

Due to the decline in the bank group’s price projections, we expect our outstanding loan balance at the June determination date will exceed the new borrowing base, resulting in a borrowing base deficiency.  We do not have additional collateral to provide to the lenders and we expect that our operating cash flows would be insufficient to repay the expected borrowing base deficiency, as required under the Credit Agreement. As such, unless we amend the Credit Agreement, we may be in default under the agreement when the borrowing base is determined in June 2012.  In addition, the elimination of the unused availability under the borrowing base, which is a factor in our working capital covenant, may result in a future default of that covenant under the Credit Agreement.  We have begun discussions with our bank group; however, until the borrowing base for June 2012 has been determined, we will not know the amount of the deficiency. As of March 31, 2012, the debt is classified as long-term as we are not in violation of any debt covenants. Should we be in violation of any covenants which have not been waived or have a borrowing base deficiency as of June 30, 2012, some or all of the debt will be reclassified to current. There are no assurances that we will be able to amend our Credit Agreement or obtain a waiver.  If we do obtain a waiver or an amendment, there can be no assurance as to the cost or terms of such an amendment.

These conditions raise substantial doubt about our ability to continue as a going concern for the next twelve months. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, the consolidated financial statements do not include any adjustments relating to the recoverability of assets and classification of liabilities that might be necessary should the Company be unable to continue as a going concern.

The liquidity issues discussed above were also considered in assessing the recoverability of our deferred tax asset. See Note 13—Income Taxes for further discussion.

Note 3—Recent Pronouncements

On June 16, 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-05, Presentation of Comprehensive Income, which revises the manner in which entities present comprehensive income in their financial statements. The new guidance removes the presentation options in Accounting Standards Codification (“ASC”) 220 and requires entities to report components of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. The ASU does not change the items that must be reported in other comprehensive income. The amendments are effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three months ended March 31, 2012.

On May 12, 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (“IFRS”). The ASU is the result of joint efforts by the FASB and IASB to develop a single, converged fair value framework—that is, converged guidance on how (not when) to measure fair value and on what disclosures to provide about fair value measurements. Thus, there are few differences between the ASU and its international counterpart, IFRS 13. While the ASU is largely consistent with existing fair value measurement principles in U.S. GAAP, it expands ASC 820’s existing disclosure requirements for fair value measurements and makes other amendments. Many of these amendments were made to eliminate unnecessary wording differences between U.S. GAAP and IFRS. However, some could change how the fair value measurement guidance in ASC 820 is applied. The ASU is effective for interim and annual periods beginning after December 15, 2011. The Company has adopted and applied the provisions of this update for the three months ended March 31, 2012. See disclosure provided in Note 8—Long-Term Debt and Note 10—Series A Convertible Redeemable Preferred Stock.

Note 4—Loss Per Common Share

Net loss per common share—basic is calculated by dividing Net loss available to common stockholders by the weighted average number of shares of common stock outstanding during the period. Net loss per common share—diluted assumes the conversion of all potentially dilutive securities and is calculated by dividing net loss available to common stockholders by the sum of the weighted average number of shares of common stock outstanding plus potentially dilutive securities. Net loss per common share—diluted considers the impact of potentially dilutive securities except in periods in which there is a loss because the inclusion of the potential common shares would have an anti-dilutive effect. A reconciliation of Loss per common share is as follows:

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Loss per common share—diluted for the three months ended March 31, 2012 excluded the effect of outstanding exercisable options to purchase 1,384,398 shares, 262,896 weighted average restricted shares outstanding, and 4,549,537 shares of Series A Convertible Redeemable Preferred Stock (34,996,440 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. Additionally, in computing the dilutive effect of convertible securities, Net loss available to common stockholders is also adjusted to add back any convertible preferred dividends and accretion unless the preferred shares are anti-dilutive. As such, there was no add back to Net loss available to common stockholders for the three months ended March 31, 2012 for Accretion of and dividends paid for Series A Convertible Redeemable Preferred Stock of $462,016 and $1,241,365, respectively, in computing Loss per common share—diluted as the preferred shares were anti-dilutive.

Loss per common share—diluted for the three months ended March 31, 2011 excluded the effect of outstanding exercisable options to purchase 1,125,318 shares, 383,222 weighted average restricted shares outstanding, and 4,148,538 shares of Series A Convertible Redeemable Preferred Stock (31,911,830 in dilutive shares, as converted, which assumes conversion on the first day of the period) because we reported a net loss available to common stockholders which caused the options and restricted shares to be anti-dilutive. There was no add back to Net loss available to common stockholders for the three months ended March 31, 2011 for Accretion of and dividends paid for Series A Convertible Redeemable Preferred Stock of $423,143 and $1,296,418, respectively, in computing Loss per common share—diluted as the preferred shares were anti-dilutive.

Note 5—Gas Properties

The method of accounting for gas properties determines what costs are capitalized and how these costs are ultimately matched with revenues and expenses. We use the full cost method of accounting for gas properties as prescribed by the SEC. Under this method, all direct costs and certain indirect costs associated with the acquisition, exploration, and development of our gas properties are capitalized and segregated into United States of America (“U.S.”) and Canadian cost centers. The Canadian cost center was fully impaired in 2009 and remains fully impaired at March 31, 2012.

Gas properties are depleted using the units-of-production method. The depletion expense is significantly affected by the unamortized historical and future development costs and the estimated proved gas reserves. Depletion for the three months ended March 31, 2012 and 2011 was $0.97 and $0.83 per Mcf, respectively.

Estimation of proved gas reserves relies on professional judgment and use of factors that cannot be precisely determined. Subsequent proved reserve estimates materially different from those reported would change the depletion expense recognized during future reporting periods. No gains or losses are recognized upon the sale or disposition of gas properties unless the sale or disposition represents a significant quantity of gas reserves, which would have a significant impact on the depreciation, depletion and amortization rate.

Under full cost accounting rules, total capitalized costs are limited to a ceiling equal to the present value of estimated future net revenues, discounted at 10% per annum, plus cost of properties not being amortized plus the lower of cost or fair value of unevaluated properties less income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to evaluate whether the net book value of our full cost pool exceeds the ceiling limitation. The ceiling test is performed separately for our U.S. and Canadian cost centers. If capitalized costs (net of accumulated depreciation, depletion and amortization) less related deferred taxes are greater than the discounted future net revenues or ceiling limitation, a write-down or impairment of the full cost pool is required. A write-down of the carrying value of the full cost pool is a non-cash charge that reduces earnings and impacts stockholders’ (deficit) equity in the period of occurrence and typically results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down is not reversible at a later date.

The ceiling test is calculated using the unweighted arithmetic average of the natural gas price on the first day of each month within the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions, as allowed by the guidelines of the SEC. In addition, subsequent to the adoption of

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ASC 410-20-25, the future cash outflows associated with settling asset retirement obligations were not included in the computation of the discounted present value of future net revenues for the purposes of the ceiling test calculation.

For the twelve months ended March 31, 2012, the unweighted arithmetic average of the Henry Hub spot market price on the first day of each month was $3.75 per Mcf, resulting in a natural gas price of $3.90 per Mcf when adjusted for regional price differentials. Based on the ceiling test performed utilizing the aforementioned prices, we recorded a $15.8 million write-down of the carrying value of our U.S. full cost pool at March 31, 2012.

Note 6—Asset Retirement Liability

We record an asset retirement obligation (“ARO”) on the consolidated balance sheets and capitalize the asset retirement costs in gas properties in the period in which the retirement obligation is incurred. The amount of the ARO and the costs capitalized are equal to the estimated future costs to satisfy the obligation using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date we incurred the abandonment obligation using an assumed interest rate. Once the ARO is recorded, it is then accreted to its estimated future value using the same assumed interest rate.

The following table details the changes to our asset retirement liability for the three months ended March 31, 2012:

The following table details the changes to our asset retirement liability for the three months ended March 31, 2011:

Note 7—Derivative Instruments and Hedging Activities

The energy markets have historically been volatile, and there can be no assurance that future natural gas prices will not be subject to wide fluctuations. In an effort to reduce the effects of the volatility of the price of natural gas on our operations, management has adopted a policy of hedging natural gas prices from time to time primarily using derivative instruments in the form of three-way collars, traditional collars and swaps. While the use of these hedging arrangements limits the downside risk of adverse price movements, it also limits future gains from favorable movements. Our price risk management policy strictly prohibits the use of derivatives for speculative positions.

We enter into hedging transactions, generally for forward periods up to two years or more, which increase the probability of achieving our targeted level of cash flows. We generally limit the amount of our natural gas derivative contracts during any period to no more than 50% to 80% of the then expected gas production for such future periods. Swaps exchange floating price risk in the future

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for a fixed price at the time of the hedge. Costless collars set both a maximum ceiling (a sold ceiling) and a minimum floor (a bought floor) future price. We have accounted for these transactions using the mark-to-market accounting method. Generally, we incur accounting losses on derivatives during periods where prices are rising and gains during periods where prices are falling which may cause significant fluctuations in our consolidated balance sheets and consolidated statements of operations.

Commodity Price Risk and Related Hedging Activities

At March 31, 2012, we had the following natural gas swap positions:

At December 31, 2011, we had the following natural gas swap positions:

At March 31, 2012, we had the following natural gas basis swap position:

At December 31, 2011, we had the following natural gas basis swap position:

Subsequent to March 31, 2012, we added the following natural gas swap positions:

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Subsequent to March 31, 2012, we added the following natural gas collar positions:

Forward Physical Sale Contract

Our production is sold at an “all-in” price which includes the market price for natural gas plus a “basis differential”. In January 2011, we agreed to sell gross volumes of 16,000 MMBtu/day of natural gas from our Pond Creek field for the period February 2011 through March 2012 through a forward physical sale contract with our existing purchaser at a price equal to the last day settlement price for the New York Mercantile Exchange (“NYMEX”) contract for the month of sale plus a basis differential of $0.15, $0.115, and $0.13 for the periods February 2011 through March 2011, April 2011 through October 2011, and November 2011 through March 2012, respectively. There were no remaining volumes at March 31, 2012. As of December 31, 2011, we had fixed the NYMEX settle on a portion of the aforementioned forward sale as follows:

The remaining volumes giving effect for the fixed amounts denoted above are as follows:

The aforementioned forward physical sale contract meets the definition of a derivative contract under ASC 815. However, it qualifies for normal purchase and sale exemption and, as such, we have elected not to record it on the Consolidated Balance Sheets (Unaudited) using mark-to-market accounting.

We have reviewed the financial strength of our hedge counterparties and believe our credit risk to be minimal. Our hedge counterparties are participants in our Existing Credit Agreement and the collateral for the outstanding borrowings under our Existing Credit Agreement is used as collateral for our hedges. We do not have rights to collateral from our counterparties, nor do we have rights of offset against borrowings under our Existing Credit Agreement.

The application of ASC 820-10-55, Fair Value Measurements, currently applies to our derivative instruments. Under the provisions of ASC 820-10-55, we estimate the fair value of our natural gas derivative contracts using the income approach. The income approach uses valuation techniques that convert future cash flows to a single discounted value. ASC 820-10-55 clarifies that a fair value measurement for an asset or liability reflects its nonperformance risk, the risk that the obligation will not be fulfilled. Because nonperformance risk includes our counterparties’ and our credit risk, we have considered the effect of credit risk on the fair value of the assets and liabilities related to the items stated below. The consideration for discounting our counterparties’ liabilities (our assets) was based on the difference between the S&P credit rating of a comparable company to our counterparties and the 13-week Treasury bill rate, both at the reporting date. The consideration for discounting our liabilities was based on the difference between the market weighted average cost of debt capital plus a premium over the capital asset pricing model and the stated interest rates of the debt instruments included in our long-term debt.

In order to estimate the fair value of our natural gas derivative contracts, a forward price curve and volatility estimates were compiled from sources that include NYMEX settlements and observed trading activity in the Over-the-Counter (“OTC”) markets. Pricing estimates for the theoretical market value of hedge positions were developed using analytical models accepted and employed by a broad cross-section of industry participants. To extrapolate future cash flows, discount factors incorporating our counterparties’ and our credit standing are used to discount future cash flows.

We did not have any transfers of assets and liabilities between Level 1 and Level 2 of the fair value measurement hierarchy during the three months ended March 31, 2012. Based on the use of observable market inputs, we have designated these types of instruments as Level 2 for ASC 820-10-55 reporting purposes. The fair value of our derivative instruments was as follows:

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The following (gains) losses on our hedging instruments included in the consolidated statements of operations and other comprehensive (loss) income (“OCI”) are as follows:

The Effect of Derivative Instruments on the Consolidated Statements of Operations and

Other Comprehensive (Loss) Income for the Three Months Ended March 31, 2011 and 2010

Accumulated comprehensive loss of $1,317,376 as of March 31, 2012 consists entirely of foreign currency translation adjustment. Accumulated comprehensive loss of $1,309,926 as of December 31, 2011 consists entirely of foreign currency translation adjustment.

Note 8 — Long-Term Debt

On November 18, 2011, our Fifth Amended and Restated Credit Agreement (the “Credit Agreement”) with a group of six banks became effective. The Credit Agreement replaced our Fourth Amended and Restated Credit Agreement and provides for revolving credit borrowings of up to $250 million with an initial borrowing base of $180 million. The borrowing base will be determined as of each June and December with the next determination scheduled to be completed by June 2012. All outstanding borrowings under the

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Credit Agreement become due and payable on November 18, 2015. In the event that the outstanding borrowings at any borrowing base determination date exceed the borrowing base (“a borrowing base deficiency”) the Company has three options in order to remain in compliance with the Credit Agreement, (i) to immediately reduce the outstanding borrowing by the amount of the borrowing base deficiency, (ii) provide additional collateral equal to the amount of the borrowing base deficiency, or (iii) make six equal monthly payments in an aggregate amount equal to the borrowing base deficiency. The Credit Agreement provides for interest to accrue at a rate calculated, at the Company’s option, at the Adjusted Base Rate plus a margin of 1.25% to 1.75% or the London Interbank Offered Rate (the “LIBOR Rate”) plus a margin of 2.25% to 2.75%. Adjusted Base Rate is defined to be the greater of (i) the agent’s base rate or (ii) the federal funds rate plus one half of one percent or (iii) the LIBOR Rate plus a margin of 1.00%. In all cases the applicable margin is dependent on the percentage of borrowing base usage. Under the Credit Agreement we are subject to certain financial covenants requiring maintenance of (i) a minimum Current Ratio, (ii) a maximum Debt Ratio and, (iii) depending on our Debt Ratio, either (a) a minimum Interest Coverage Ratio or (b) a minimum Fixed Charge Ratio. The Current Ratio of consolidated current assets (defined to include amounts available under our borrowing base) to consolidated current liabilities (defined to exclude up to $1.5 million in accrued and unpaid preferred dividends) is not permitted to be less than 1.0 to 1.0 as of the end of any fiscal quarter. The Debt Ratio (defined as funded debt at the end of each fiscal quarter to trailing four quarter consolidated EBITDA) at the end of each fiscal quarter cannot exceed 4.25 to 1.0 through the quarter ending December 31, 2012 and 4.0 to 1.0 thereafter. If our Debt Ratio at the end of each fiscal quarter is above 3.5 to 1.0, then the Fixed Charge Ratio (defined as consolidated EBITDA less capital expenditures to consolidated net cash interest expense for the four preceding quarters) is applicable and cannot be less than 1.25 to 1.0. If our Debt Ratio at the end of each fiscal quarter is 3.5 to 1.0 or less, the Interest Coverage Ratio (defined as consolidated EBITDA to consolidated net cash interest expense plus letter of credit fees accruing during the preceding four quarters) is applicable and cannot be less than 2.75. Consolidated EBITDA is defined as earnings (loss) before deducting net interest expense, income taxes, depreciation, depletion and amortization and also excludes non-recurring charges and other non-cash charges deducted in determining net income (loss), which would include unrealized gains and losses from a change in the market value of open derivative contracts and non-cash gains, losses or adjustments and charges on any oil and gas hedge transaction, including those resulting from the requirements of ASC Topic 815, as a result of changes in the fair market value of oil and gas hedge transactions. We are also subject to covenants restricting or prohibiting cash dividends and other restricted payments, transactions with affiliates, incurrence of debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities, and liens on properties. Cash dividends on our preferred stock above the $2 million discretionary amount allowable under the Credit Agreement are permitted if, following any such cash payment our availability is equal to or greater than 15% of the then current borrowing base and our Debt Ratio is less than 3.5 to 1.0. There are no restrictions associated with the payment of PIK dividends on our preferred stock. At March 31, 2012, we are in compliance with the aforementioned Credit Agreement covenants. We are currently in the process of completing the June borrowing base determination which is discussed in Note 2—Liquidity and Going Concern Considerations.

As of March 31, 2012 and December 31, 2011, we had $149.5 million and $157.9 million, respectively, of borrowings outstanding under our Credit Agreement, resulting in a borrowing availability of $30.5 million and $22.1 million, respectively, under our $180 million borrowing base, subject to compliance with covenants. For the three months ended March 31, 2012 we borrowed $7.4 million and made payments of $15.8 million under the Credit Agreement. For the three months ended March 31, 2011 we borrowed $7.2 million and made payments of $9.2 million under the Credit Agreement. The rates at March 31, 2012 and December 31, 2011 were 2.79% and 2.84% per annum, respectively. For the three months ended March 31, 2012 and 2011, interest on the borrowings averaged 2.90% and 3.41% per annum, respectively.

The following is a summary of our long-term debt at March 31, 2012 and December 31, 2011: